The present invention relates to the field of 3D property modeling and simulation of an oil reservoir. Such models use computer software and various field measurements to predict various properties of the reservoir, such as the presence of oil and its ability to flow. Developing a 3D mapping of the wellbore is considerably less expensive than performing actual wellbore testing.
Large amounts of capital are spent every year drilling, evaluating, testing and completing new oil and gas wells. The elimination of unnecessary data gathering and the gathering of necessary additional information is often the subject of disagreements when decisions are being made throughout the drilling/exploration process. The tendency is to over-purchase new technologies with the assumption that a better answer can be reached.
The identification and evaluation of hydrocarbon productive intervals such as oil and gas reservoirs in a formation traversed by a well bore or borehole have historically been done by lowering instruments into a well and measuring petrophysical parameters such as formation resistivity and density. During the drilling, borehole samples from the formation are collected by a process called core sampling. These samples are then analyzed in laboratories and various parameters are measured to determine petrophysical properties.
The results of these measurements are then numerically processed using empirical relationships in order to calculate water saturation, porosity and permeability, which describe key formation properties. These variables are key indicators of hydrocarbon volume and hydrocarbon productivity, respectively. Based on these values, petrophysicists use their experience to make a judgment and to determine the potential presence of commercial hydrocarbons.
There are currently a number of reservoir computer modeling programs available, such as the Petrel modeling software marketed by Schlumberger. Such modeling programs divide the reservoir into a large number of three-dimensional cells. Using data obtained from logging tools along with seismic measurements and rock core sample analysis, the programs perform mathematical analyses to estimate the permeability, porosity, water saturation, and other properties for each cell.
One of the measures of flow capacity of a well is the value of porosity times cell height, or KH. KH profile logs have been modeled successfully with vertical wellbores to predict flow characteristics in a wellbore. Today, many wellbores contain both vertical and horizontal or slanted wellbores. It has been found that existing modeling techniques used in vertical wellbores do not produce accurate KH profiles when applied to high-slant and horizontal wellbores. It would be desirable to provide the ability to be able accurately to generate 3D models for any type of wellbore including horizontal and slant wellbores.